Not applicable.
Not applicable.
Production of oil and gas from subterranean formations is dependent on many factors. These hydrocarbons must usually migrate through a low permeable formation matrix to drain into the wellbore. In many formations, the permeability is so low that it hinders the well""s production rate and overall potential. In other wells, the near wellbore is damaged during drilling operations and such damage often results in less than desirable well productivity. Hydraulic fracturing is a process designed to enhance the productivity of oil and gas wells or to improve the injectivity of injection wells.
In the fracturing process, a viscous fluid is injected into the wellbore at such a rate and pressure as to induce a crack or fracture in the formation. Once the fracture is initiated, a propping agent, such as sand, is added to the fluid just prior to entering the wellbore. This sand laden slurry is continuously injected causing the fracture to propagate or extend. After the desired amount of proppant has been placed in the reservoir, pumping is terminated, and the well is shut-in for some period of time. Later, the well is opened, initially to recover a portion of the treating fluid and later the hydrocarbons. The hydraulic fracturing process is successful because the hydrocarbons are now able to drain into the propped fracture that serves as a highly conductive channel leading directly to the wellbore.
The fracturing treatment is dependent, in part, on the properties of the fracturing fluid. The fluid must attain high viscosities, minimize solvent loss to the formation matrix (known in the art as fluid loss control) and adequately suspend the proppant. The fracturing fluid is prepared by first dissolving polymers in a solvent. Generally, the solvent is water which is often made saline or contains other additives to minimize clay expansion and migration in the formation matrix. The fracturing fluids are typically composed of water soluble polymers, crosslinking agents, breakers and other additives, such as surfactants, which are employed to prevent well specific problems such as water blocks or emulsions.
The water soluble polymers most often used are either guar gum or a guar gum derivative. The derivatives usually are hydroxypropyl guar (HPG), carboxymethyl guar (CMG) or carboxymethylhydroxypropyl guar (CMHPG). Less often, cellulose derivatives such as hydroxyethyl cellulose (HEC) or carboxymethylhydroxypropyl cellulose are used, but are generally cost prohibitive. Lastly, biopolymers such as xanthan gum have been used in rare occasions. At polymer concentrations usually ranging from 0.24 to 0.72 weight percent, the viscosities of the solutions made from these polymers are too low in most instances to be used as a fracturing fluid. As a reference, a 0.48 weight percent polymer solution (i.e. without a crosslinking agent) generally provides a viscosity of less than 50 centipoise (cps) at 511 sxe2x88x921. The viscosity of polymer solutions may be enhanced by the addition of a crosslinking agent. Typical crosslinking agents contain titanium, zirconium or boron ions. These agents work by binding the polymer chains together. Since the viscosity is derived exponentially from the polymer""s molecular size, binding the polymers together dramatically increases their size and consequently, the viscosity.
Traditionally, polymer concentration has been viewed as the important factor in obtaining fracturing fluid stability, i.e. maintenance of viscosity at an acceptable level, at a prescribed temperature, for a defined period of time. The convention in the art has been to increase polymer concentration or loading to increase stability for long pumping times or for treating formations at high temperatures. For example, in wells having high temperatures in excess of about 350xc2x0 F. (177xc2x0 C.), the polymer loading may exceed 0.72 weight percent. At the other extreme, a useful fracturing fluid could not be obtained at polymer concentrations of less than 20 pounds per thousand gallons (ppt), or 0.24 weight percent. In practice, an increase in viscosity above the polymer solution is not obtained and many times the polymer may precipitate from solution when crosslinker is added. However, it would be highly desirable to have stable, crosslinked fracturing fluids using polymer loadings of 20 ppt less.
The surprising discovery has been made that crosslinked fracturing fluids having substantially reduced polymer loadings can be made that have performance equivalent to conventional crosslinked fracturing fluids. The fluids of the present invention include modified polymers having randomly distributed anionic substituents which yield high viscosity. The modified polymers may be crosslinked with suitable crosslinking agents to form viscous gels that are stable at polymer concentrations as low as 0.12 weight percent. The fluids of this invention provide many advantages in that equivalent fracturing fluid performance may be obtained at reduced overall treatment costs. Reduced polymer loadings may also result in less damage to the fracture sand pack and the surrounding subterranean formation after the fracturing treatment.
Not applicable.
The invention described below is a modified hydraulic fracturing fluid and method of its use to stimulate oil and gas wells. Fracturing fluids are conventionally made of water soluble polymers which are crosslinked in order to produce sufficient viscosity to create a fracture and to place a propping agent into the created fracture. To serve these functions properly, it is believed in the art that the fluid must maintain a critical minimum viscosity. Fracturing fluid systems have been developed so that the critical minimum viscosity is maintained for various time periods at various temperatures. Generally, fluids with viscosity values exceeding 100 cps at 105 secxe2x88x921 are thought to be adequate for fracturing wells. It is desirable for all of the fracturing fluid to be pumped into the formation before the viscosity of the initially pumped fluid reaches that minimum. To obtain such performance, fracturing fluid systems normally contain polymer concentrations greater than the C* concentration for the polymer.
The C* concentration is described as that concentration necessary to cause polymer chain overlap. Suitable polymer chain overlap to effectively obtain a crosslinked gel is thought to occur when polymer concentration exceeds the C* concentration. In fact, the higher the polymer concentration, the greater the polymer chain overlap and the greater the gel strength after crosslinking. The literature often recites the C* concentration for guar to be about 0.19 to 0.22 weight percent polymer. Consequently, the lowest concentration of polymer typically used in hydraulic fracturing applications to form crosslinked gels has been about 0.24 weight percent or 20 pounds per thousand gallons (ppt). However, such gels typically have very limited stability at the temperatures frequently encountered in fracturing applications.
CMG and CMHPG contain carboxylate groups which are anionically charged except in strong acid. These anionically charged groups tend to repel away from one another. Because they are chemically bound to the polymer, repulsion of the anionic groups also causes the polymer to occupy a much larger volume than the unsubstituted guar polymer. Surprisingly, it has been found that some carboxylated guar derivatives have C* values as low as 0.06 weight percent. These polymers were found to make suitable crosslinked gels that were applicable for hydraulic fracturing processes at concentrations as low as 0.12 weight percent or 10 ppt. Although previously such fluids were not stable at temperatures higher than ambient, it has surprisingly been discovered that polymer loadings of about 0.14 weight percent are stable up to 150xc2x0 F. (65xc2x0 C.) and useful gels with stability up to 175xc2x0 F. (79xc2x0 C.) can be made with as little as 0.18 weight percent polymer or 15 ppt.
The invention described herein has several advantages. Lower loadings of polymer can be used to obtain equivalent fracturing fluid performance at reduced overall treatment costs. Reduced polymer loadings may also result in less damage to the surrounding subterranean formation after the fracturing treatment. Guar based polymers are attributed with causing damage to both the fracture sand pack and reducing the effective fracture width. The present invention permits substantial reduction in the amount of polymer injected into the formation while maintaining optimal fluid properties for creating the fracture.
Reducing the C* concentration for a polymer requires modification of the conventional guar polymers. In the practice of the present invention it is preferred that the guar polymer is high yielding. High yielding guar polymers can be obtained in many ways, including a) using premium grade guar as the starting material to which anionic groups are chemically added; and/or b) selecting processing parameters that provide better uniformity in placing the anionic substituents on the guar polymer backbone; and/or c) additional processing steps, including ultrawashing to remove impurities and refine the polymer. While using premium grade guar as the starting material is one way to obtain high yielding polymers in accordance with this invention, their use is not essential. The preferred polymers in accordance with the present invention are high yielding guars having randomly distributed anionic substituents. The most preferred polymers are high yielding guars having randomly substituted carboxymethyl substituents, for example CMG and CMHPG. Although CMG and CMHPG have been commercially available for a number of years, the conventional products have not been high yielding and in general do not produce the results described herein.
When forming the fracturing fluid, the polymer loading is most preferably in the range of about 0.12 to about 0.24 weight percent. The high yielding guar polymer is normally added to an aqueous fluid which may contain a variety of additives. Careful selection of additives must be made because the polymer has groups which are anionic and charge association by counter cations is possible. If cation groups are present, less charge repulsion between the anionic groups on the guar polymer will occur, resulting in less polymer chain expansion. Consequently, the present invention requires that certain cation producing additives, such as potassium chloride (KCl), a clay stabilizer, be excluded from the fracturing fluid. However, quaternary ammonium salts based on tetramethylammonium halides such as tetramethylammonium chloride (TMAC) can be used as a substitute. At relatively low loadings as little as 0.1 weight percent, TMAC is effective on clays without being detrimental to the fluids of the present invention. In forming the fracturing fluid of this invention, other conventional additives may be included, such as breakers, stabilizers, surfactants, among others well known to those skilled in the art. However, such additives should be selected so as not to interfere with the interactions of the anionic groups on the polymer.
Crosslinking is also an important part of the fracturing fluid. For the present invention, a suitable crosslinking agent is one which will increase the viscosity of the polymer solution by forming a complex with the anionic substituent on the polymer. Suitable crosslinkers include titanium, boron and zirconium based crosslinkers. Preferred crosslinkers include zirconium based compounds which will effectively form a complex with carboxylated polymers such as CMG or CMHPG. Preferred zirconium based crosslinkers include, zirconium lactate, zirconium glycolate and zirconium lactate triethanolamine. The most preferred zirconium based crosslinker is zirconium lactate.
When using zirconium based crosslinkers, the gelation kinetics are strongly dependent on the bicarbonate content of the aqueous fluid. Bicarbonate concentrations near 500 ppm often require fluid temperatures in excess of 140xc2x0 F. (60xc2x0 C.) to initiate full gelation. To overcome this temperature dependency, the fluid pH can be adjusted to about 5.0 or less to reduce the bicarbonate content. At a pH of about 5, gelation occurs within acceptable times at ambient temperature. For higher temperature applications, the presence of bicarbonate may be desirable in that it can be used to delay gelation temporarily, thereby increasing shear tolerance of the fluid during pumping. When using bicarbonate to delay gel formation, the fluid pH can be increased to exceed 9.0. The preferred pH range of the fluid was established by testing and found to be between about 3.5 and about 12.0. Gelation of the fluid at low pH allows pumping the gel with CO2 for either gas assist or foam treatments. It is within the skill in the art to optimize the gelation kinetics by adjusting the pH and additives in the fluid.
The following examples are presented to show the utility of the invention and are not intended to limit the invention in any way.